Sonic data can provide useful inputs to completion of unconventional reservoirs for enhanced productivity. Unconventional reservoirs are characterized by low permeability. Economical production of such gas-shale (or oil-shale) reservoirs is made possible by proper selection of hydraulic fracturing stages and perforation clusters that contribute to the hydrocarbon productivity.
Gas-shale (or oil-shale) reservoirs may be characterized by orthorhombic anisotropy with 9 independent elastic constants in the presence of triaxial formation stresses or vertically aligned fractures. In the absence of formation stresses and fractures, shale lithology can be described by transversely-isotropic (TI) anisotropy with five independent elastic constants, assuming that the vertical pilot well is parallel to the TI-symmetry X3-axis and the X1-X2 is the cross-sectional isotropic plane. Referred to these anisotropic axes, conventional workflows to determine minimum horizontal stress as a function of vertical depth require estimates of elastic constants C13 and C33. While the elastic constant C33 is directly obtained from the monopole compressional head wave slowness (or velocity) in a vertical pilot well, the elastic constant C13 is estimated from other sources, such as, plane wave velocity measurements on oblique core plugs or combining wellbore sonic data from both a vertical and deviated sections in the same shale lithology as described in Jocker, J., M. Feria, F. Pampuri, E. Wielemaker, S. Sunaga, 2013a, TI anisotropic model building using borehole sonic logs acquired in heterogeneous formations: SEG Technical Program Expanded Abstracts 2013, SEG International Exposition and 83rd Annual Meeting, Houston, Tex., Sep. 22-27, 2013, pp. 305-309 and Jocker, J., M. Feria, F. Pampuri, E. Wielemaker, 2013b, Seismic anisotropy characterization in heterogeneous formations using borehole sonic data: Paper 166463, SPE Annual Technical Conference and Exhibition, 30 September-2 October, New Orleans, La., or invoking approximate rock physics models that need to be calibrated against core data from the same shale lithology interval. A major limitation of conventional workflows is that sonic data from an enormously large volume of earth (on the order of hundreds of feet) is assumed to be representative of an effectively homogeneous and anisotropic formation. However, it is known that shale reservoirs are significantly heterogeneous in their mechanical properties and averaging elastic properties over large volumes does not reflect spatial variations that need to be accounted for in a proper placement of fracturing stages and perforation clusters for an economic production of hydrocarbons. Generally, dimensions of fracturing stages and perforation clusters are on the order of several feet to several inches along the producing well and it is, therefore, important to identify heterogeneities on this scale.